Fracturing while tripping

ABSTRACT

A drill string includes drill pipe and a modular fracturing sub. A processor can control the drill string to drill a wellbore to some desired depth. The drill string is positioned at a desired location in the wellbore and a section of the wellbore is hydraulically isolated, forming a cavity. Existing fluid may be evacuated from the cavity and fracturing fluid injected into the cavity until a desired level of fracturing is attained. Retrievable packers are used for the hydraulic isolation. A pump evacuates the existing fluid via ports in the fracturing sub. The ports may also be used when injecting fracturing fluid. Seismic sensors may be distributed along the drill string to monitor fracture growth. Logging-while-drilling tools may be integrated into the drill string. Fluid from the lower portion of the wellbore is blocked by a lower sealing unit on a bottomhole assembly.

BACKGROUND

Driven by demand and corresponding rising oil and gas prices, shale oiland gas production has become economically attractive and given rise toa new era of production. The characteristics of shale reservoirs maytypically be described as having extremely low permeability (e.g.,100-600 nano-Darcys), low porosity (e.g., 2-10%), and moderate gasadsorption (gas content 50-150 scf/ton). To achieve economicalproduction and enhance recovery, large numbers of horizontal wells andmassive, multistage hydraulic fracturing treatment (HFT) jobs have beenperformed in shale reservoirs.

A fracturing operation is normally done after a well is drilled and thedrill pipe and bottomhole assembly (BHA) have been removed from thewell. To prepare for the fracturing operation, an interval of interestis chosen, the interval is hydraulically isolated by at least twopackers, and fracturing (“fracking”) fluid is injected into the spacebetween the packers at high enough pressures to initiate and propagateone or more fractures in the formation.

SUMMARY

A drill string includes drill pipe and a modular fracturing sub. Aprocessor can control the drill string to drill a wellbore to somedesired depth. The drill string is positioned at a desired location inthe wellbore and a section of the wellbore is hydraulically isolated,forming a cavity. Existing fluid may be evacuated from the cavity andfracturing fluid injected into the cavity until a desired level offracturing is attained. Retrievable packers are used for the hydraulicisolation. A pump evacuates the existing fluid via ports in thefracturing sub. The ports may also be used when injecting fracturingfluid. Seismic sensors may be distributed along the drill string tomonitor fracture growth. Logging-while-drilling tools may be integratedinto the drill string. Fluid from the lower portion of the wellbore isblocked by a lower sealing unit on a bottomhole assembly.

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion. Embodiments are described with reference to the followingfigures. The same numbers are generally used throughout the figures toreference like features and components.

FIG. 1 is a schematic drawing of a drill string disposed in a wellboreand used to perform a fracturing operation, in accordance with thepresent disclosure.

FIG. 2 is a schematic drawing of the drill string of FIG. 1 particularlypositioned in the wellbore adjacent to and sealing off a zone ofinterest, in accordance with the present disclosure.

FIG. 3 schematically shows a detailed view of a fracturing sub, inaccordance with the present disclosure.

FIG. 4 schematically shows the drill string of FIG. 1 and multiplereceivers at different locations in the drill string, in accordance withthe present disclosure.

FIG. 5 schematically shows a zone of interest in a wellbore as well astwo stations within the zone of interest, in accordance with the presentdisclosure.

FIG. 6 is a flowchart for a fracturing operation using a drill string,in accordance with the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for the purpose ofsimplicity and clarity and does not in itself dictate a relationshipbetween the various embodiments and/or configurations discussed.Moreover, the formation of a first feature over or on a second featurein the description that follows may include embodiments in which thefirst and second features are formed in direct contact, and may alsoinclude embodiments in which additional features may be formedinterposing the first and second features, such that the first andsecond features may not be in direct contact.

Some embodiments will now be described with reference to the figures.Like elements in the various figures may be referenced with like numbersfor consistency. In the following description, numerous details are setforth to provide an understanding of various embodiments and/orfeatures. However, it will be understood by those skilled in the artthat some embodiments may be practiced without many of these details andthat numerous variations or modifications from the described embodimentsare possible. As used here, the terms “above” and “below”, “up” and“down”, “upper” and “lower”, “upwardly” and “downwardly”, and other liketerms indicating relative positions above or below a given point orelement are used in this description to more clearly describe certainembodiments. However, when applied to equipment and methods for use inwells that are deviated or horizontal, such terms may refer to a left toright, right to left, or diagonal relationship, as appropriate. It willalso be understood that, although the terms first, second, etc. may beused herein to describe various elements, these elements should not belimited by these terms. These terms are only used to distinguish oneelement from another.

The terminology used in the description herein is for the purpose ofdescribing particular embodiments only and is not intended to belimiting. As used in the description and the appended claims, thesingular forms “a”, “an” and “the” are intended to include the pluralforms as well, unless the context clearly indicates otherwise. It willalso be understood that the term “and/or” as used herein refers to andencompasses any and all possible combinations of one or more of theassociated listed items. It will be further understood that the terms“includes,” “including,” “comprises,” and/or “comprising,” when used inthis specification, specify the presence of stated features, integers,steps, operations, elements, and/or components, but do not preclude thepresence or addition of one or more other features, integers, steps,operations, elements, components, and/or groups thereof.

As used herein, the term “if” may be construed to mean “when” or “upon”or “in response to determining” or “in response to detecting,” dependingon the context. Similarly, the phrase “if it is determined” or “if [astated condition or event] is detected” may be construed to mean “upondetermining” or “in response to determining” or “upon detecting [thestated condition or event]” or “in response to detecting [the statedcondition or event],” depending on the context.

A system and method to perform fracturing operations using a drillstring is disclosed herein. While a well is drilled,logging-while-drilling (LWD) tools may be used to characterize theformation and determine one or more zones of interest for fracturingoperations. The drill string may then be pulled back to a determinedzone of interest and used to isolate at least a portion of that zone ofinterest. Fracturing fluid is conveyed through the drill pipe andinjected into the isolated zone, causing the surrounding formation tofracture. In one or more embodiments, micro-seismic receivers are placedat different locations along the drill string and used to monitor theprogress of the fracturing operation, which allows the operation to becontrolled.

When a horizontal well is drilled, the operation generally starts with avertical section drilled down to a certain depth. From there the well is“side-tracked” to form a deviated section that eventually lands in thereservoir formation at the depth of interest. Once in the desiredreservoir formation, an operator attempts to drill the well in anoptimum direction and depth, which for “thin” reservoirs is somedistance above the oil-water contact or some distance below the upper(shale) layer boundary. This tends to maximize the oil and gasproduction from the well. In some cases, for example where the reservoiris relatively thick and the permeability is relatively low, one mayfracture the reservoir to increase the production rate. Since fracturesusually penetrate on the order of hundreds of meters, the fracturing isgenerally used on formations with thicknesses comparable to the extentof fracture penetration. This is commonly the case with shalereservoirs, which are generally very thick and have permeabilities onthe order of nano-Darcys. Other applicable reservoirs are tightcarbonates, which can be several hundred meters thick and, by theirnature, have low permeability.

At the time of fracturing the vertical section of the well is usuallyalready cased so that the formation layers penetrated by that section ofthe well are already hydraulically sealed. The horizontal section may ormay not be cased. The embodiments disclosed herein pertain to open-holefracturing in which the horizontal section is not cased, but othercontemplated embodiments are not limited to open-hole completions. In atypical fracturing operation, pipes are used to extend the casing downto the zone that is targeted for fracture. The zone of interest isisolated from the remainder of the well before fracturing fluid ispumped into the well. Operationally, a drilling rig is used to installthe pipes, any casing, and any isolation mechanisms such as packers.Since rig operations are expensive and time-consuming, rig operationtime (i.e., costs) can be reduced by performing the fracturing operationin the same “trip” that is used to finalize the drilling operation (orat least before the rig is removed from the well).

FIG. 1 shows a section of horizontal well 110 being drilled using adrill bit 120, a bottomhole assembly (BHA) 130, and drill pipes 140,collectively referred to herein as a “drill string”. BHA 130 containsLWD tools that may be used to measure formation properties such asporosity, permeability, oil saturation, and other formation evaluationparameters used to decide whether to fracture a well and, if so, overwhat interval of the well. The LWD tools may also include a gamma raytool that is used to “mark” the depth for going back to a particulardepth of interest. The LWD tools may also comprise an acoustic tool thatcan be used to measure geomechanical properties of the rock. Thesemeasurements are useful in designing fracturing parameters such aspressure, flow rate, etc.

BHA 130 also comprises one or more fracturing subs 150 which provide themechanical components to perform the fracturing operation. Once it isdecided to perform the fracturing operation, BHA 130, which hasgenerally drilled past the zone of interest 210 (see FIG. 2), is pulledback to zone of interest 210 to perform the fracturing operation. Thispartial tripping (out) operation is guided by the gamma ray tool toensure the fracturing sub 150 is in the zone of interest 210.

The zone of interest 210 can be isolated using retrievable packers 220and 230, for example, which are part of fracturing sub 150. The drillingfluid in the isolated annulus of zone 210 is pumped into the annulusabove (or below) the zone 210. Next, the fracking fluid is introducedinto the isolated zone 210 at sufficiently high pressure to cause theformation to fracture. The high pressure fluid exerts radial pressurearound the borehole wall which, in combination with the maximum andminimum stresses normally present in the formation, causes the rock tobreak (i.e., initiate a fracture) and propagate the fracture into theformation. The packers 220, 230 are released and the BHA is moved to thenext location (station) within the zone of interest 210 or to the nextzone of interest, if any, and the operation is repeated. When the zonesof interest are fractured, the tripping out operation continues and thedrill string is removed from the well. In this manner the drilling andfracturing has been performed in a single (i.e., last) trip.

FIG. 3 shows a detailed view of a fracturing sub 150. Sub 150 comprisesmultiple spacing sections 310 and other components. Thus, sub 150 ismodular, with the number of modules being a design parameter chosen tofit a particular purpose. Each section 310 is typically the same lengthas a standard drill pipe (i.e., a 30 ft. section or three such sectionsfor a total length of 90 ft.). As FIG. 5 shows, the zone of interestspanning the depths 510 a to 510 b can be divided into multiple stationsspanning the depths 520 a to 520 b, 520 c to 520 d, etc. The zone ofinterest in FIG. 5 has been divided into two stations, but there can beas many stations as desired. The drill string stops at each station andperforms the fracturing operation before moving to the next station. Thespan of each station is generally limited by the length of sub 150,which in turn depends on the number of sections 310 and other componentsdescribed below.

As stated above, fracturing sub 150 has at least two retrievablepackers, shown as packers 320 in FIG. 3. The at least two packers 320are spaced apart to establish the operational length of a station (e.g.,520 a to 520 b). If the length of the station is known a priori, thenumber of sections and the locations of packers 320 can be determinedbefore the BHA 130 is run into the well on the last trip. If the lengthof the station is not finalized before BHA 130 enters the well, multiplepackers may be provided, but, in operation, only the pair spanning thedesired station distance is activated for each hydraulic isolation. Inone embodiment, a fixed length (packer separation) is used for thestations, eliminating the cost and complexity of extra packers.

The sub 150 also comprises at least one pumping unit 330, located closeto the top (i.e., uphole end) of BHA 130. Pumping unit 330 is operatedafter packers 320 have been activated and hydraulic isolation has beenestablished to pump the drilling fluid in the isolated zone out intoother portions of the well annulus. The pumping unit 330 has one or morevents (ports) 332 that allow fluid to flow from the isolated zoneannulus into pumping unit 330. Vent 332 can be opened and closed oncommand or it can be spring-loaded, with applied pressure causing it toopen when the pump is on, while the spring closes it once the pumppressure drops below a certain threshold. Thus, while pumping thedrilling fluid out, vent 332 is open, allowing the drilling fluid in theisolated zone annulus to be evacuated. In some cases it may be desirableto treat the formation wall for more efficient (typically imminent)fracturing operations. This may include acidization or treatment fluidsthat destroy the mud cake previously formed on the formation wall. Ifthis is desired, the operative fluids are pumped from surface into theisolated zone. Once their operative effects are completed, theirby-products may be pumped out of the isolated zone annulus into anotherportion of the well annulus using pumping unit 330.

In addition, sub 150 also comprises a sealing unit 340 that may be usedto isolate the bottom (i.e., lower end) of sub 150 from the trailing(i.e., lower end of) BHA 130 and any other piping that may extendfarther down. Sealing unit 340 can be or comprise a valve, for example,that can be actuated on command. This valve is used to hydraulicallyseal the bottom of sub 150 prior to operating pumping unit 330 andremoving the drilling fluid in the isolated zone annulus. In anotherembodiment, the sealing unit 340 may operate using a sealing surface anda sealing ball that can be delivered to the sealing surface, therebyforming a seal.

When an operator is ready to commence the actual fracturing operation,the fracturing fluid is pumped through drill pipes 140 and into theisolated zone. The fracturing fluid may contain the customary additivesused in fracturing operations. A pumping rate is pre-determined toensure a desired pressure is obtained inside the isolated zone, causingthe formation to initiate a fracture. The applied pressure is furthermaintained to ensure the fracture is propagated to a desired length.This pumping rate can be adjusted as deemed necessary during the courseof the fracturing operation. In one embodiment the flow into theisolated zone is through vents 332. In another embodiment the flow intothe isolated zone is through a dedicated port which may have beenenlarged to accommodate higher flow rates (not shown). In all cases,when the fracturing fluid is pumped into the isolated zone, the normalflow path to the drill bit is closed off so that the pressure is onlyapplied to the isolated zone. The close-off can be done by a dedicatedvalve, for example (not shown).

The sub 150 may also comprise one or more micro-seismic receivers 350that are used to detect and record the acoustic vibrations generatedfrom the fracturing of the rock. These receivers 350 are commonly usedin fracturing operations and their signals are processed to determinethe lengths and directions of the fractures. The receivers 350, carriedon sub 150, are sensitive to acoustic signals generated during thefracturing operation, but they are also sensitive to the events thathappen close to sub 150. In particular, the receivers 350 can be used toaccurately pinpoint the locations where the fractures initiated andtheir initial propagation directions away from the well.

To have information from more distant locations, one may place multiplereceivers 350 at several locations along the wellbore, as well as on theearth's surface. FIG. 4 shows the drill string with drill bit 120, BHA130, fracturing sub 150, and multiple receivers 350 at differentlocations. With this arrangement, and possibly having one or morereceivers 350 on the surface (not shown), it is possible to detect ampleseismic signal to process and map the fractures. In one embodiment, theprocessing is done in real-time and operational parameters such as thepumping rate may be adjusted accordingly.

FIG. 6 is a flowchart for one embodiment to perform fracturingoperations using a drill string. A drill string comprising drill pipe, abottomhole assembly, and a drill bit, wherein the bottomhole assemblycomprises a fracturing sub, is provided (602). A wellbore is drilled toa desired depth using the drill string (604). The drill string ispartially withdrawn to a desired location in the wellbore (606). Asection of the wellbore is hydraulically isolated and a cavity betweenthe drill string and the wall of the isolated section of the wellbore isformed using the fracturing sub (608). The cavity is evacuated until afirst desired pressure within the cavity is attained (610). Fluid isinjected into the cavity until a second desired pressure within thecavity is attained (612). The drill string is removed from the wellbore(614).

Some of the techniques described above can be performed by a processor.The term “processor” should not be construed to limit the embodimentsdisclosed herein to any particular device type or system. The processormay include a computer system. The computer system may also include acomputer processor (e.g., a microprocessor, microcontroller, digitalsignal processor, or general purpose computer) for executing any of themethods and processes described above.

The computer system may further include a memory such as a semiconductormemory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-ProgrammableRAM), a magnetic memory device (e.g., a diskette or fixed disk), anoptical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card),or other memory device.

Some of the methods and processes described above, can be implemented ascomputer program logic for use with the computer processor. The computerprogram logic may be embodied in various forms, including a source codeform or a computer executable form. Source code may include a series ofcomputer program instructions in a variety of programming languages(e.g., an object code, an assembly language, or a high-level languagesuch as C, C++, or JAVA). Such computer instructions can be stored in anon-transitory computer readable medium (e.g., memory) and executed bythe computer processor. The computer instructions may be distributed inany form as a removable storage medium with accompanying printed orelectronic documentation (e.g., shrink wrapped software), preloaded witha computer system (e.g., on system ROM or fixed disk), or distributedfrom a server or electronic bulletin board over a communication system(e.g., the Internet or World Wide Web).

Alternatively or additionally, the processor may include discreteelectronic components coupled to a printed circuit board, integratedcircuitry (e.g., Application Specific Integrated Circuits (ASIC)),and/or programmable logic devices (e.g., a Field Programmable GateArrays (FPGA)). Any of the methods and processes described above can beimplemented using such logic devices.

While the embodiments described above particularly pertain to the oiland gas industry, this disclosure also contemplates and includespotential applications such as water wells or other wells primarilydrilled to produce fluid from low permeability formations.

The foregoing outlines features of several embodiments so that thoseskilled in the art may better understand the aspects of the presentdisclosure. Those skilled in the art should appreciate that they mayreadily use the present disclosure as a basis for designing or modifyingother processes and structures for carrying out the same purposes and/orachieving the same advantages of the embodiments introduced herein.Those skilled in the art should also realize that such equivalentconstructions do not depart from the scope of the present disclosure,and that they may make various changes, substitutions, and alterationsherein without departing from the scope of the present disclosure.

The Abstract at the end of this disclosure is provided to comply with 37C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature ofthe technical disclosure. It is submitted with the understanding that itwill not be used to interpret or limit the scope or meaning of theclaims.

While only certain embodiments have been set forth, alternatives andmodifications will be apparent from the above description to thoseskilled in the art. These and other alternatives are consideredequivalents and within the scope of this disclosure and the appendedclaims. Although only a few example embodiments have been described indetail above, those skilled in the art will readily appreciate that manymodifications are possible in the example embodiments without materiallydeparting from this invention. Accordingly, all such modifications areintended to be included within the scope of this disclosure as definedin the following claims. In the claims, means-plus-function clauses areintended to cover the structures described herein as performing therecited function and not only structural equivalents, but alsoequivalent structures. Thus, although a nail and a screw may not bestructural equivalents in that a nail employs a cylindrical surface tosecure wooden parts together, whereas a screw employs a helical surface,in the environment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of theclaims herein, except for those in which the claim expressly uses thewords ‘means for’ together with an associated function.

What is claimed is:
 1. A method, comprising: providing a drill stringcomprising drill pipe and a fracturing sub; drilling a wellbore to adesired depth using the drill string; positioning the drill string at adesired location in the wellbore; hydraulically isolating a section ofthe wellbore and forming a cavity between the drill string and the wallof the isolated section of the wellbore using the fracturing sub; andinjecting fluid into the cavity until a desired pressure within thecavity is attained.
 2. The method of claim 1, wherein the positioningthe drill string comprises placing the fracturing sub adjacent to a zoneof interest.
 3. The method of claim 2, wherein the positioning the drillstring further comprises placing the fracturing sub adjacent to asubsurface station within the zone of interest.
 4. The method of claim1, wherein the hydraulically isolating comprises actuating two or moreretrievable packers.
 5. The method of claim 1, further comprisingpumping fluid out of the isolated section.
 6. The method of claim 5,further comprising passing the fluid through one or more ports in thefracturing sub.
 7. The method of claim 1, wherein the desired pressurecorresponds to a desired level of fracturing.
 8. The method of claim 1,further comprising providing one or more seismic sensors and monitoringthe fracturing using the one or more seismic sensors.
 9. The method ofclaim 8, wherein the one or more sensors comprises a plurality ofsensors distributed along the drill string.
 10. A system, comprising: adrill string comprising drill pipe and a fracturing sub; and a processorlocated at the earth's surface or carried on the drill string capableof: drilling a wellbore to a desired depth using the drill string;positioning the drill string at a desired location in the wellbore;hydraulically isolating a section of the wellbore and forming a cavitybetween the drill string and the wall of the isolated section of thewellbore using the fracturing sub; and injecting fluid into the cavityuntil a desired pressure within the cavity is attained.
 11. The systemof claim 10, wherein the fracturing sub comprises two or moreretrievable packers.
 12. The system of claim 10, wherein the fracturingsub comprises a pump.
 13. The system of claim 10, wherein the fracturingsub comprises one or more ports.
 14. The system of claim 13, wherein theone or more ports are activated remotely by command or automaticallyactivated.
 15. The system of claim 10, wherein the fracturing subcomprises one or more spacers.
 16. The system of claim 10, wherein thefracturing sub comprises two or more modules.
 17. The system of claim10, further comprising one or more seismic sensors carried on anddistributed along the drill string.
 18. The system of claim 10, furthercomprising logging-while-drilling tools integral with the drill string.19. The system of claim 10, further comprising a bottomhole assemblyhaving a lower sealing unit.
 20. The system of claim 19, wherein thelower sealing unit is selected from the group consisting of a valve anda sealing surface/sealing ball combination.